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Passive microseismic monitoring provides a non-invasive method of monitoring deformation and changes in the stress distribution within a rock mass. Recently the petroleum industry has applied and focussed such studies on the monitoring of hydraulic fracturing stimulation: the fracturing of a reservoir by the injection of a high pressure fluid into reservoir causing the rock to fracture, increasing the permeability. However, the development of passive seismic monitoring of a fully operational oil field has been slow largely due to economic constraints limiting the geophone array to be deployed within a single vertical borehole. The challenge is thus to refine the seismic methods applied to datasets from the vertical arrays and to explore the extent to which further investment in more sophisticated seismic arrays would advance the understanding of the reservoir architecture and evolution. The Ekofisk reservoir in the North Sea provides an excellent opportunity to address these issues and is the focus of this study. Discovered in 1969 the Ekofisk field is located within the Central Graben of the Norwegian North Sea and is operated by Conoco-Phillips. It was one of the world's first economically viable chalk reser- voirs and comprises two main oil bearing intervals: the Ekofisk and Tor Formation chalks, separated by a relatively impermeable siliceous chalk. Since the onset of production in 1971, the reservoir has expe- rienced appreciable subsidence. A water injection program was initiated but has done little to mitigate the problem. In April 1997, one of the first hydrocarbon passive micro seismic monitoring studies was undertaken over an 18 day period at Ekofisk in an attempt to understand the mechanism of deformation. Data were acquired using a six station geophone array deployed in a vertical borehole. Fundamental to the study of seismicity at any scale is the accurate determination of the event source. Events for borehole microseismics are usually located using a ID velocity model, P- and S-wave arrival times and the polarisation azimuth of the P-wave particle motion. However, in the case of all sensors being deployed within a vertical or near-vertical bore hole such analysis leads to an inherent 1800 ambiguity in source location. In this study, this ambiguity is removed by using the back-projecion of the dip of the particle motion from multiple stations until they converge on one side of the well or the other as a priori information to constrain the initial source location. The procedure is developed and tested using a dataset acquired from another field during hydraulic fracture stimulation, where event locations are known. Applying this procedure to the Ekofisk dataset 627 events are successfully located with coherent features clustering around production/waterflooding wells and fractures. Most are located less than 250 m away from the monitoring well and at a depth of ",3 km in the Ekofisk chalk formation. Little seismicity is observed from the underlying Tor Formation chalk, which is separated from the Ekofisk Formation by an impermeable layer of siliceous chalk. There is no evidence of seismicity in the overburden. Repeating earthquakes (multiplets) are identified and relatively re-located in order to enhance the resolution of active features and gain further insight into the mechanism of deformation. Qualitative analysis of the waveforms of the multiplets shows a number of potential mechanisms such as production/waterflooding induced activity, fault re-activation and stress triggering. Having established precise hypocentres for the Ekofisk microseismicity the final goal of this study is to gain information along the source-receiver raypath using a shear wave splitting study of anisotropy. An automated shear wave splitting approach is applied to the Ekofisk dataset yielding 1125 reliable measurements. A number of near-vertical fracture sets with fracture strike orientations of NE-SW and W-SE agrees with previous core based studies of Ekofisk. In summary, this thesis shows that a single borehole deployment of geophones can be used to gather detailed information about the spatial and temporal variation in seismicity in a hydrocarbon setting. The seismic data can then be used via study of seismic anisotropy to place fundamental new constraints on the state of stress, mineral alignment, layering of sedimentary structures or the presence of aligned fracture sets all of which have profound implications for reservoir management.

An integrated, multi-disciplinary approach was developed to examine waterflooding processes in deepwater stacked turbidite reservoirs. Fluid flow in porous rocks was reviewed both at the pore and the reservoir section scales. The importance of a favourable mobility ratio for a stable oil/water displacement was highlighted. This information guided our choices for fluids characteristics to use in our fluid flow simulation models. A geological review of deepwater turbidite reservoirs provided a sound understanding of their geological characteristics, with a special emphasis on their impact on fluid flow within the reservoir. The vertical permeability distribution across the reservoir was identified as having a crucial impact on waterflooding efficiency in turbidite reservoirs. Permeability distribution within a channel element of a stacked turbidite reservoir follows three characteristic trends: homogeneous distribution, fining upward distribution, and coarsening upward distribution. A series of idealised reservoir models, representative of a single flow unit within a turbidite reservoir, was built. The idealised models represented the three different permeability distributions commonly found in turbidites and another model was added to simulate bottom drive waterflooding. Two scenarios were run on the models: water injection with pressure support and water injection where the pressure dropped by a maximum of 1500 psi. The change in Vp was around 4 to 5% regardless of the reservoir geology or the pressure variations. Pressure change has a global dimming effect on the P-wave velocity. It happens very briefly after the start of the simulation and spreads across the whole reservoir. Change in Vp due to pressure decline was around -0.5% and could not be detected on the synthetic seismic. The waterfront is easily interpreted both on 4D cross-section and 4D attribute maps. A realistic turbidite geological model based on the Ainsa II outcrop was built. The model was populated with rock characteristics of a turbidite reservoir on the West of Africa. The model was then up-scaled and fluid flow simulation was performed. Permeability values and NTG distribution played a major role in the advance of the waterfront inside the reservoir and controlled its shape and location. Petrophysical modelling showed that P-waves velocity would increase by up to 7% due to the substitution of oil by water and suggested that it can be extremely sensitive to water saturation changes. Even the smallest changes (less than 10%) would have a noticeable effect on Vp values, which is of crucial importance when time-lapse seismic is to be used in a quantitative way. Synthetic seismic was created using three different frequencies (35 Hz, 62 Hz, and 125 Hz). On 3D seismic sections, different channels within the reservoir were resolved separately on the high resolution seismic. Tuning phenomenon is observed for the three modelled frequencies due to the presence of very thin beds (1-2 meter thick). The interpretation of the OOWC or the MOWC on those sections is challenging because the reflections at the fluids front are obscured by reflections from geological interfaces. The complex geology of the reservoir resulted in 3 different RMS seismic amplitude maps showing an increasing degree of heterogeneity as the seismic dominant frequency increased. Interpretation of MOWC on time-lapse seismic cross-sections and maps is challenging and the inclusion of different attributes in the interpretation workflow might be necessary in order to assess the complexity of the waterflooding signature. Time-lapse seismic monitoring of waterflooding processes in deepwater turbidite reservoirs requires sound a-priori knowledge of the geology of the reservoir. On the other hand, an accurate interpretation of the time-lapse seismic signature of Waterflooding can improve our understanding of the reservoir characteristics. Therefore, the task should be performed by multi-disciplinary teams, where geologists, reservoir engineers, and geophysicists work closely together.

Surface geochemistry, the measurement of near-surface hydrocarbons, has been used by the petroleum industry for more than 80 years to explore for subsurface petroleum deposits. The fact that hydrocarbons generated deep in the sedimentary section from thermally mature organic rich rocks can migrate to the near-surface in measurable concentrations is well documented but the methods currently used by industry to extract and measure these near-surface migrated hydrocarbons have not been rigorously tested. One of the key goals in this PhD research effort is to determine the best procedures to remove migrated hydrocarbon gases (C1 to C5) from near-surface marine sediments with minimal fractionation based on laboratory experiments and field calibration studies. A second key goal is evaluate procedures to evaluate nearsurface sediment gasoline range hydrocarbons (C5 to C10). The middle boiling point range hydrocarbons have been largely ignored in surface geochemistry and could contain valuable information to determine subsurface petroleum generation, migration, and entrapment. Lastly, it is extremely important to understand how best to evaluate and integrate the near-surface gas and gasoline range measurements into an overall understanding of the petroleum charge system, specifically the source, maturation, and migration elements for evaluating prospect charge. Empirical observations from the global surface geochemical database and laboratory experiments demonstrate that several of the surface geochemical methods currently used by industry do not accurately remove the nearsurface migrated gases thus providing biased and incorrect results. The acid extraction (Horvitz adsorbed method), microdesorption, and ball mill (occluded) bound sediment gas extraction methods all provided gas compositions and isotopic ratios significantly different than the charge gases. The extracted bound gases contain elevated wet gas (C2 to C5) relative to the charge gases. These results are similar to what was noted in the global surface geochemistry database. In addition, the laboratory results indicate we do not fully understand sediment bound gas process. Thus the bound gases may not properly reflect the composition or isotopic ratios of the migrated hydrocarbons. Three interstitial sediment gas methods were examined as part of my research efforts, two canned headspace with different preparation and laboratory procedures; and a new extraction method designated as the disrupter. One of the headspace methods and the new disrupter gas extraction method provided gas compositions and isotopic ratios very similar to the charge gases. One of the headspace can methods provided highly variable gas compositions due to can leakage and preparation procedures. In general the interstitial hydrocarbon gases when properly collected and evaluated can provide critical information on the presence of mature source rock at depth. The gasoline range plus hydrocarbons are rarely examined in surface geochemical studies due to the great difficulty in extracting this boiling point range of hydrocarbons. The SPME method, in conjunction with the disrupter chamber, has been shown from laboratory evaluation to accurately remove and reflect gasoline range hydrocarbons in marine sediments. Choosing the most efficient fiber, optimal boundary conditions, and limitations is very critical. Early field testing has shown the gasoline range hydrocarbons are heavily bacterially altered in most near-surface marine. Despite these issues, the gasoline range plus hydrocarbons have great potential in determining the source and maturity of the migrated hydrocarbons in near-surface marine sediments. Thus near-surface sediment gases and gasoline range hydrocarbons, when properly collected and extracted, can be used as indicators of subsurface generation and entrapment as shown in the observation with the global surface geochemical database and laboratory experiments.

This thesis describes a detailed geochemical evaluation of the petroleum fluids in the Greater Birba Area in the South Oman Salt Basin located in South of Sultanate Oman. These crude oils were found in the Infracambrian (Precambrian-Cambrian) Ara group carbonates (Upper Huqf supergroup), which are sealed by anhydrites. The reservoirs are heavily shattered due to halokinetic movement and so the migration of oil to these sealed carbonate slabs was probably vertical through these halokinetic faults. The Greater Birba area oils are characterized by large variations in some of the important properties. API gravity ranges from 23.70 to 51.00. Dead oil and live oil viscosities vary a lot from a minimum of 1.50 cp and 0.92 cp to a maximum of 188 cp and 41.03 cp respectively. The acidity of the oil (TAN) varies from a low TAN of 0.11 mgKOH/g oil to a high TAN value of 1.24 mgKOH/g oil. Most of the oils show high TAN values (>0.50) and only few oils show low TAN values. Sulphur content also varies a lot and ranges from 0.78 wt% in a black oil to 4.7 wt% in a gas condensates and generally negatively correlated with API gravity. Therefore, an important aim of this study was to improve the understanding of the underlying controls on these properties using both geochemistry and PVT modelling. A comprehensive study was undertaken on these oils using twenty two oil samples, twenty reservoir core samples, five gas samples and data from eleven PVT reports. Hydrocarbons molecular geochemistry, gasoline range hydrocarbon data, bulk composition and isotopic data as well as PVT modelling were employed in this study to evaluate and characterize crude oils and attempt to identify the controls on observed fluid properties variations in the Greater Birba area. Most of the crude oils in the Greater Birba area show typical characteristics of oils sourced from evaporite-carbonate source facies deposited in hypersaline and highly reducing environment, except for two oil samples, one from BBNl (from A3C reservoir unit), which might be contaminated and the other is from Kaukabl (from A 1 C reservoir unit). Some of these characteristics are high sulphur content, low asphaltene contents, high relative abundance of Pregnanes, gammacerane, and C35 homohopanes as well as other geochemical features. Various maturity parameters (e.g. MPI and C29 (S+R) aPPI (aaa+app) in CI5+ Saturated and aromatic hydrocarbons suggested that these oils were generated from a source rock in the middle of oil window (O.8-0.9%R). No evidence was found for water washing and biodegradation effects in the studied oils. There was no evidence to prove or deny thermochemical or bacterial sulphate reduction, although general observations suggest that this is less likely to occur in the Greater Birba area. Number of facies sensitive parameters and maturity sensitive parameters as well as isotopic data show that these oils are genetically related and only minor variations exist between them, largely due to minor facies variations. These small variations can not account for the large variations observed in bulk properties. Two samples were exceptional from the above statement 05 from BBNl (reservoir A3C), which is probably a contaminated sample with most likely younger oil and 015 from Kaukab 1 (reservoir Al C) and this is different because it is from Al C reservoir unit which is in contact with middle Huqf source rocks. PVT modelling, gasoline range hydrocarbons data and absolute concentrations of biomarkers suggest that the main control behind the variations observed in the petroleum fluids in the Greater Birba area were mixing of oil and gas condensate with a dry gas probably derived from highly mature pre-salt source rocks. This oilcondensate- gas mixing increased the bubble point pressure above reservoir pressure in some of the oil accumulation in the studied area (e.g. main Birba Field), which resulted in the formation of two phases in these accumulations. Sulphur content was probably controlled by both oil-condensate mixing and the minor facies variations between the original oils. The variations in the absolute concentrations of biomarkers in the oils were mainly controlled by dilution effects caused by mixing of oils with alkane rich condensate charge. The formation of a gas phase and related Phase fractionation effects might be responsible for the significant variations in acidity, API gravity and the distribution of alkylphenols. Birba oils (A4C oils of well BB 1, and BB2) were suggested to have migrated longer distance than the other oils on the basis of alkylcarbazoles isomer distribution.

Biodegradation of crude oil in reservoirs has major economic consequences. While the effects of biodegradation are empirically well known, the processes involved, the fraction of oil destroyed and the critical factors controlling degradation remain obscure. A suite of oils and reservoir extracts from the Liaohe basin, NE China, was analyzed to investigate the effects and controls of biodegradation on petroleum composition. The aims of this project were to further our understanding of the factors which influence the biodegradation of crude oils, and the processes by which these factors interact and to assess the role played by biodegradation in controlling the composition of a wide range of crude oils. The geological settings of the study area have been addressed in detail, including structural and stratigraphic characteristics, source rock and reservoir characteristics, tectonic evolution and hydrocarbon generation history, formation water composition. A single source and similar maturity make the study area an ideal site to investigate the constraint of biodegradation. Systematic changes seen as marked gradients in petroleum bulk composition, component concentrations and molecular indicators have been observed in biodegraded oil columns. The susceptibilities of several aromatic hydrocarbon, alkylcarbazole and alkylphenol isomers to biodegradation have been discussed for the first time in this thesis. The author also addressed the biodegradation effects on many classical geochemical evaluation procedures such as those involving facies and maturity assessmenat nd on the physical and chemical properties of petroleum. The variation in the degree of biodegradation at different sites of the column is controlled by water leg size, with a higher level of degradation being associated with a thicker water leg. The supply of nutrients from the water leg is thought to have a significant impact upon the degree of biodegradation. In addition to water leg size/nutrient supply, the compositional gradients are also controlled by the relative rate of mixing of fresh and degraded oils. The conceptual biodegradation model proposed couples geochemical and geological factors to provide a coherent approach to ascertain the impact of degradation on petroleums and to help to reliably predict biodegradation risk for an exploration target. Our data suggest that biodegradation occurs within a narrow region near the base of the oil column, probably at the oil water contact (OWC), and that in this reservoir there has been a late charge of oil to the top of the column. The mixing of oils through continuous charging and the diffusion of hydrocarbons towards the OWC, and the diffusion of metabolites of degraded oil away from the reaction site may be considered as the most important factor controlling the biodegradation process. Based on an oil charging-biodegradation model (Larter et al., 2003) mass balance calculation has been carried out and the results indicate at level 5 biodegradation up to 50% of petroleum mass has been depleted, beyond this level of biodegradation loss of oil mass is less significant but structural rearrangements are important.

The objective of the research project was to investigate the use (incorporating the environmental impacts) of ammonia and amines to minimise acidic corrosion in the overhead system of a Crude Distillation Unit without the danger of these additives forming corrosive hydrochloride deposits. It is hoped that the information obtained will enable refiners to select amines or amine mixtures that reduce both acidic and hydrochloride deposit corrosion to a level acceptable in today's refinery. Additonally, a framework has been developed to allow the refiner to select which of these chemicals has the lowest environmental impact in a particular refinery. A Computer Model that accurately predicts the pH profile of the acidic condensate of the overhead condenser system was developed. Although many similar models exist in the literature and in the marketplace, this model incorporates two novel aspects - the raising of the water dew point temperature by hydrochloric acid and the partitioning of amines between the water and hydrocarbon phases. The Knudsen Effusion technique was used to determine previously unknown vapour pressure data for the hydrochlorides of several commercially used amines and to validate existing data for ammonium chloride. This data can be used to predict the temperatures in the Crude Distillation Unit at which hydrochloride deposition occurs. With this information, the refiner should now be able to minimize the danger of hydrochloride salt corrosion in the overhead system of the Crude Distillation Unit. Furthermore, by combining the amine pH profiles from the computer model with their hydrochloride vapour pressure data it was possible to identify two amines (DMIPA and MOP A) that had a superior ability to neutralise the acidic condensate without the danger of hydrochloride deposition. A laboratory scale chamber was designed that accurately reflects the deposition of ammonium chloride and amine hydrochlorides in the overhead system of the Crude Distillation Unit. This Deposition Chamber was used firstly to validate assumptions made with the Knudsen Effusion data and secondly to check whether pure vapour pressure data could accurately predict the actual hydrochloride deposition temperatures in the Crude Distillation Unit. It also showed that the use of pure vapour pressure data to predict amine hydrochloride deposition temperatures in the Crude Distillation Unit is valid for structurally dissimilar amines. However, the observed hydrochloride deposition temperature of a mixture of two structurally similar amines was found to be approximately 5°C higher than the theoretical deposition temperature predicted from the vapour pressure data, indicating that they should not be used together.

Commercial nonylphenol ethoxysulphonate (NPEOS), octylphenol ethoxysulphonate (OPEOS) surfactant formulations and mixtures of alkyl aryl sulphonate and NPEOS surfactant formulations, are used for enhanced oil recovery (EOR). The surfactants have been analysed by liquid chromatography (LC), liquid chromatography-mass spectrometry (LC-MS) and matrix assisted laser desorption ionization mass spectrometry. Mixedmode C1 8/SAX and C8/SAX columns were used for both liquid chromatography and liquid chromatography-mass spectrometry analyses of NPEOS and OPEOS. NPEOS and alkyl aryl sulphonate surfactant mixtures were separated using a mixed-mode C4/SAX column. Matrix assisted laser desorption ionization mass spectrometry (MALDI-MS) spectra were obtained using either alpha-cyano-4-hydroxycinnamic acid or 2,5-dihydroxybenzoic acid as matrix with the addition of lithium chloride to simplify the mass spectra obtained. Data obtained from each method indicate that the NPEOS formulation has an ethoxymer chain length ranging from 2-13 units with average of 6.26. This is in broad agreement with earlier studies, although the range was reported as 2-15. However, the data obtained suggest that the OPEOS formulation has an ethoxymer chain length ranging from 1-8 ethoxymer units with an average chain length of 3.67. This is in contrast to earlier studies carried out by LC only, which suggested that the chain length ranged from 2 to 6 ethoxymer units with an average of 3.6. A method for the extraction of NPEOS and OPEOS from sea-water and reagent water, and alkyl aryl sulphonate from sea-water only, using graphitised carbon black (GCB) solid phase extraction (SPE) cartridges has also been developed. In the last section of this thesis the chemical oxidation of NPEOS used Fenton's reagent and biological oxidation of NPEOS using a microorganism (Paracoccus halodenitrificans) is reported. The intermediate products formed in the chemical oxidation have been identified and characterized by LC, LC-ES-MS and MALDI/MS techniques. The major products formed are dicarboxylic acids and single carboxylic acids. The aerobic biodegradation of NPEOS was carried out over five days. Theoxygen uptake was measured each day. The biodegradation intermediate products were analysed by LC and data indicate that the same products were formed as those from the chemical oxidation of NPEOS.

The world's proven reserves of crude oil will be depleted in 42 years at the current rate of consumption. Oil refiners are under considerable economic and environmental pressure to improve the efficiency of refining and the quality and definition of products. Statistical and fundamental models are extensively used to more accurately model the important refinery processes such as Fluidised Catalytic Cracking (FCC). A major problem with the fundamental approach is that FCC feedstocks are by definition heavy petroleum fractions, and as such constitute highly complex mixtures of aromatic and aliphatic hydrocarbons. Gas chromatography (GC) analysis of heavy petroleum fractions reveals a broad 'hump' of unresolved compounds termed an Unresolved Complex Mixture (UCM) of hydrocarbons. Conventional instrumental techniques alone are unable to elucidate the composition of UCMs, they are simply too complex. Oxidative degradation of UCMs has already been used with some success to selectively oxidise aliphatic and aromatic UCMs to reveal some of the structures incorporated in UCMs from various natural and anthropogenic sources. Ruthenium tetroxide (RUO4) attacks aromatic rings at the ipso-carbon of aromatic moieties. Unsubstituted aromatic carbon is oxidised to CO2 whereas substituents are preserved as carboxylic acids. "Retro-structural analysis" involves reconstruction of the products of oxidation to reveal the original molecule or 'average' molecule. However, previous studies have highlighted problems with the recovery of products from die oxidation of hydroaromatic compounds. Hydroaromatic compounds contain an alicyclic ring attached to an aromatic ring e.g. tetralin. This study presents evidence that (theoretically) data from RUO4 oxidation FCC feedstocks can make a significant improvement to the accuracy of FCC modelling at BP Amoco. RUO4 oxidation and work-up procedures were developed further in an attempt to overcome problems with 'losses' of oxidation products from hydroaromatic compounds, including an improved carbon dioxide trap. Several novel hydroaromatic compounds and a diaromatic compound proposed in a previous study as being 'average' UCM components were synthesised and fully characterised by GC, GCMS, FTIR and NMR spectroscopy. The compounds synthesised were 6-cyclohexyltetralin, l-(3'- methylbutyl)7-cyclohexyltetralin, 1-n-nonyl-7-cyclohexyltetralin and 1-/n-nonyl-7- cyclohexylnaphthalene. RUO4 oxidation of the synthetic compounds and commercial tetralin revealed that while losses of between 70 and 50% of the expected water soluble dicarboxylic acids are observed, these losses can be at least partially accounted for by the 'over oxidation' of carboxylic acids to produce smaller carboxylic acids. For example, the RUO4 oxidation of tetralin produces 1,6-hexanedioic acid as a major product but significant amounts of 1,5-pentanedioic acid is observed along with trace amounts of 1,4- butanedioic acid. Smaller acids are likely to be undetected or lost as butyl esters during the work-up. Where 2-n-nonyl-1,6-hexanedioic acid was produced, decanoic and nonanoic acid as well as 1,5- pentanedioic acid and 1,4-butanedioic acid were observed corresponding to oxidation of the 2- position on the dicarboxylic acid. The three major products from RUO4 oxidation of ln-nonyl-7-cyclohexylnaphthalene were partially oxidised compounds including 2-(l-oxo-n-decane)-4-cyclohexylbenzoic acid, showing that the oxidation of diaromatic compounds in UCMs gives more complex oxidation products. This is consistent with previous studies where diaromatic UCMs were oxidised to give a more complex 'oxidised UCM' rather than simple carboxylic acids. The observation of monocarboxylic acids in oxidation products from the alicyclic portion of a hydroaromatic compound has not previously been reported. This represents a new source of monocarboxylic acids in the RUO4 oxidation products of UCMs and should be taken into account when oxidising UCMs likely to contain a significant proportion of hydroaromatic structures, such as hydrotreated FCC feedstocks. The synthesis and oxidation of di-substituted teiralins has increased the understanding of RuG4 oxidation products from UCMs and consequently furthered the use of RUO4 as a potentially useftjl tool in the elucidation of FCC feedstock compositions and other aromatic UCMs.

Petroleum migration pathways through a basin are determined by the three-dimensional distribution of discontinuous sealing surfaces, which are usually parallel to bedding. The petroleum migrates below the sealing surface taking the structurally most advantageous route. The three-dimensional distribution of migration pathways within the petroleum system can be modelled on a personal computer using a program based on the parameters developed during the research summarised in this thesis. Application of the model to the Paris, Williston, West of Shetlands and Wessex Basins demonstrates that a good correlation can be made between predicted pathways and discovered accumulations using simple models. Migration pathways form a dense network overlying hydrocarbon generating areas in the central parts of basins. Towards the basin margins they commonly become increasingly focused into discrete pathways by the sealing-surface morphologies. The Paris and Williston Basin research showed how relatively minor structuring of geological strata can result in a significant focusing of pathways. Eventually these pathways may reach the surface as shown by seepages. Research in the Wessex Basin revealed that reverse modelling of pathways from seeps assists in the prediction of the location of leaking accumulations. Deflection of the pathways from the structurally most advantageous route below the sealing surface may be caused by lateral sealing barriers due to facies variation in the carrier rock below the seal, fault juxtaposition, or cross-formational seals such as salt intrusions. Deflection of pathways also occurs where there are hydrodynamic conditions in response to topography-driven groundwater flow.

Cyclone separators have been described in detail and, although substantial research has been performed on solid/gas devices, the use of cyclones for gas/liquid separation has been comparatively ignored; this is particularly true for higher concentrations of liquid and for degassing applications. Consequently no generic models are available which will predict separation efficiency or pressure drop for all designs of cyclone. A novel design of axial flow cyclone called WELLSEP was examined for the purpose of degassing. This design was not believed to be optimal and no design criteria or performance prediction models were available for it. An experimental programme was therefore produced and executed to investigate changes in geometry and the affect of fluid dynamics. Changes to the length, vortex finder and swirl generator were examined first and then one design was selected and tested over a number of liquid flow rates, Gas Void Fractions (GVFs) and liquid extractions. Data was collected from the experiments which assisted in the development of semi-empirical models for the prediction of pressure drop and separation efficiency. These models could be used in the design of WELLSEP. Geometric and fluid dynamics changes have both been shown to influence the performance of the tested cyclone. The principal conclusions that have been drawn from this research are: Of the tested designs, the design based upon a 30mm vortex finder diameter, settling chamber length of three times the diameter of the cyclone and a four start helix gave the optimum separation efficiency over the greatest range of conditions. The separation efficiency is affected by the superficial liquid velocity and the liquid extraction but not the GVF. The dimensionless pressure drop coefficient (Euler number) is a function of liquid extraction and GVF. It may also be a function of the superficial liquid velocity but it is unproven by this research.

The factors which influence the performance characteristics of diamond impregnated core bits and roller cone bits are examined, and actual field drilling data are analysed to determine these factors. Methods for selecting the appropriate bit type for optimised drilling are also highlighted. The importance of core drilling to the exploration and exploitation of the earth's natural resources and to the integrity of engineering structures is highlighted. An investigation of the slim hole continuous core drilling system and its application in the oil and gas exploration is analysed. The highly successful integration of oilfield, mining and geotechnical exploration technologies in a special investigation programme includes several elements which are important in the application of slim hole methods for oil and gas exploration are analysed. Many of the technical issues associated with a slim hole approach have been addressed in the development and application of the drilling, and coring equipment and systems. The project has given an opportunity to evaluate the advantages and disadvantages, merits and limitations for applying different drilling and associated technologies for deep hole construction to safety.

The behaviour of gas condensate flow in the porous media is distinctly different from that of gas-oil flow. The differences are attributed to the difference in fluid properties, phase behaviour, and condensation and vaporisation phenomena that distinguishes gas condensate fluids from the aforementioned fluid types. These differences manifest themselves into an important flow parameter that is typically known as relative permeability. Relative permeability is known to be related to the phase saturation, and the interfacial tension (EFT). Also, at high phase velocities, its reduction with increasing velocity, known as Forchheimer (turbulence) or inertia effect, is well documented. An unconventional behaviour of gas condensate fluids has been experimentally proven in Heriot-Watt laboratory and confirmed by other experimental studies performed elsewhere. These tests have shown that at intermediate velocities, before the inertia becomes significant, the gas and the condensate relative permeabilities are significantly improved by increase in velocity. This phenomenon is referred to as the rate-effect. None of the conventional relative permeability models include this experimentally proven favourable rate effect. In this work the flow of gas condensate fluids in porous media is modelled with emphasis on near wellbore conditions. Theoretical, empirical as well as simulational investigations are used to improve the present technology on the treatment of the flow of gas condensate in reservoirs. The use of X-ray or y-ray devices to monitor saturation profile during displacement experiments is investigated and the appropriate test conditions leading to reliable measured relative permeability data are determined. The regimes of the gas condensate flow at the core level, where the rate effect is evident, are investigated using the concept of Reynolds number. Then a mechanistic flow model, where the flow of gas condensate fluids is assumed to follow an annularmist flow criterion, is presented to capture the essence of the rate effect in perforations. The favourable EFT and rate effects are incorporated into the modelling of gas condensate relative permeability by correlating it with capillary number (I\Ic). Two forms of the correlation are presented. The impact of EFT and Ne together with the Forchheimer (inertia) on well deliverability is thoroughly investigated using the above correlation. The gas condensate relative permeability correlation is combined with the Forchheimer effect and used in a specially modified version of a commercial simulator, Eclipse 300V 98a development, to investigate the impact of IFT, Nc, and inertia on well productivity. The impact is found to accelerate production from gas condensate reservoirs. At practical production rates, the significance of the impact on phase recoveries cannot be ignored regardless of reservoir fluid richness or absolute permeability.